Wellhead assemblies are utilized in the oil and gas industry to connect any number of different apparatus to a wellbore. A tubing hanger or dognut axially supports a production string inside production casing in the wellbore. A tubing rotator, operatively connected to the tubing hanger, is incorporated into the wellhead assembly to rotate the production tubing. Rotation of the tubing avoids localized wear for minimizing tubing failures arising from contact during reciprocation or rotation of a rod string therein, such as for operating an artificial lift pump in the production string.
It is known to provide integrated wellhead assemblies having upper and lower portions, either cast as a single unit, welded together or otherwise integrally coupled. The upper portion generally incorporates blow-out preventers for sealing a bore through the upper portion. The blow out preventers generally include one or more sets of rams, including but not limited to blind rams that seal against one another and rod rams that seal against an outer surface of a polished rod connected to the artificial lift pump, or both. A flow tee may be incorporated into the upper portion of the assembly to provide a secondary flow path fluidly connected to a bore of the wellhead assembly. The tubing hanger is generally supported in the lower portion of the wellhead assembly. The lower portion may further comprise ports which are in fluid communication to an annulus between production casing and production tubing, supported by the tubing hanger, in the wellbore. The tubing hanger may include sealing elements that isolate the annulus from the bore of the upper portion of the wellhead.
Conventional tubing rotators are typically separate units which are assembled between the blowout preventer (BOP) and the tubing head. Integrated tubing rotators are known however generally provide insufficient torque to rotate a tubing string in deviated wellbores or in deep wellbores, such as in wellbores greater than about 6000 ft. Tubing rotators, in general, have insufficient torque capacity for use in either deep wellbores, whether straight or deviated, such as directional and slant wells, or in deviated wellbores in general. Additionally, the gearing of tubing rotators is typically a complicated arrangement of a series of worm gears and a planetary gear box, which provides a number of different locations for potential leakage.
Repair of conventional tubing rotators typically requires pulling the tubing to surface and clamping the tubing thereat to allow the tubing rotator to be removed for repair or replacement. This is generally a time consuming and costly procedure which requires additional equipment, such as a service or drilling rig.
Conventional tubing rotators may comprise a load shoulder on a mandrel, which is operatively connected to the tubing string, for supporting the load thereof when the mandrel is set down on axial roller bearings for rotation of the mandrel and the tubing string, with or without a dognut. In U.S. Pat. No. 5,964,286 to Cuppen, the load shoulder is connected at a top of the mandrel or is integral with the mandrel extending through the bore of a rotator body. The mandrel is connected directly to the tubing string or is connected to a dognut which is connected to the tubing string. Where the load shoulder is integral with the mandrel, the rotator body cannot be lifted off the mandrel however, in embodiments where the load shoulder is not integral, split rings engage grooves in the mandrel with the load shoulder to hang the tubing string with the dognut unseated. The addition of the split rings allows the mandrel to lift the dognut and thereafter to be seated onto the rotator. In another embodiment taught by Cuppen, the load shoulder is a split ring engaged between a shoulder on the mandrel and the top of a ring gear.
There is interest in wellhead assemblies that incorporate sealing systems, such as blowout preventers, and tubing rotators capable of providing sufficient torque to rotate tubing in deep wellbores, in deviated wellbores and in deep and deviated wellbores. There is interest in low profile tubing rotators that fit within conventional wellhead footprints or flange diameters. In particular there is interest in flexible systems that can be incorporated with a variety of different tubing heads and which have a more simplified and robust design. Further still, there is interest in tubing rotators that can be repaired without having to pull the production string from the wellbore.